Hydrocarbons (e.g., oil and natural gas) in a hydrocarbon-bearing zone of a subterranean formation can be reached by drilling a wellbore into the earth, either on land or under the sea that penetrates into the hydrocarbon-bearing formation. Such a wellbore can be used to produce hydrocarbons or as an injector well to inject a fluid, e.g., water or gas, to drive the relevant fluids/gasses into a production wellbore. Typically, such a wellbore must be drilled thousands of feet into the earth to reach the hydrocarbon-bearing formations. Usually, but not always, the greater the depth of the well, the higher the natural “static” temperature of the formation.
After drilling an openhole, the next step is referred to as “completing” the wellbore. A wellbore is sometimes completed openhole, that is, without cemented casing in place adjacent to the producing formations. More typically, however, as part of the well completion process, a metal pipe, known as “casing” is positioned and cemented into place in the openhole.
The main purpose of cementing the casing is to stabilize the wellbore against collapse and to prevent undesirable migration of fluids along the wellbore between various zones of subterranean formations penetrated by the wellbore. Where the wellbore penetrates into a hydrocarbon-bearing zone of a subterranean formation, the casing can be perforated to allow fluid communication between the zone and the wellbore. A zone of a wellbore that penetrates a hydrocarbon-bearing zone that is capable of producing hydrocarbon is referred to as a “production zone.” The casing also enables subsequent or remedial separation or isolation of one or more production zones of the wellbore, for example, by using downhole tools such as packers or plugs, or by using other techniques, such as forming sand plugs or placing cement in the perforations.
Whether the wellbore is openhole or cased, various procedures are often employed to complete the wellbore in preparation for production of hydrocarbons. For example, one common procedure is gravel packing to help prevent sand and fines from flowing with the hydrocarbon produced into the wellbore. This particulate material can be damaging to pumps and other oilfield equipment and operations. Another example of a common procedure to stimulate the flow of hydrocarbon production from the hydrocarbon-bearing zones is hydraulic fracturing of a formation. This procedure is often referred to as “fracking,” to provide an improved flow path for hydrocarbons to flow from the hydrocarbon-bearing formation to the wellbore. It is also common, for example, to gravel pack after a fracturing procedure, and such a combined procedure is sometimes referred to as a “frac-packing.”
After a well has been completed and placed into production, from time to time it is helpful to workover a well by performing major maintenance or remedial treatments. Workover includes the stimulation or remediation of a well to help restore, prolong, or enhance the production of hydrocarbons. During well servicing or workover, various treatment procedures may be used, including for example, gravel packing, hydraulic fracturing, and frac-packing as mentioned for well completion.
All of these procedures, from drilling the wellbore, to completion, to workover, employ appropriate fluids. During the initial drilling and construction of the wellbore, the fluids are often referred to as drilling fluids. In other stages, such as well completion, servicing, or workover, the fluids introduced into the wellbore are often referred to as treatment fluids, completion fluids, or workover fluids. A well treatment fluid is used for a wide range of purposes, such as stimulation, isolation, or control of reservoir gas or water or formation particles. As used herein, however, a “treatment fluid” includes any appropriate fluid to be introduced into a wellbore, whether during drilling, completion, servicing, workover, or any other such stage.
More particularly, for example, a treatment performed to enhance or restore the productivity of a well is called a stimulation treatment. Stimulation treatments fall into two main groups, matrix treatments and hydraulic fracturing treatments.
Matrix treatments are performed below the reservoir fracture pressure and generally are designed to restore or enhance the natural permeability of the reservoir in the near-wellbore area. Matrix operations can include treating the formation with an acid to dissolve some of the acid soluble rock material. For various reasons known in the art, is sometimes desirable to perform a matrix treatment with a viscosified or gelled fluid.
Fracturing treatments are performed above the fracture pressure of the reservoir formation and create a highly conductive flow path between the reservoir and the wellbore. In general, hydraulic fracturing involves injecting a fracturing fluid through the wellbore and into an oil and gas bearing subterranean formation at a sufficiently high rate of fluid flow and at a sufficiently high pressure to initiate and extend one or more fractures in the formation. To conduct hydraulic pressure through the wellbore, the fracturing fluid must be relatively incompressible under the treating conditions. In addition, because of the large quantities of fracturing fluid required, the fracturing fluid is preferably based on readily-available and plentiful fluid. Thus, the typical fracturing fluid is based on water.
The fracturing fluid is injected through the wellbore at such a high flow rate and under such high pressure that the rock of the subterranean formation that is subjected to the hydraulic treatment literally cracks apart or fractures under the strain. When the formation fractures, the pressure is relieved as the fracturing fluid starts to move quickly through the fracture and out into the formation. The theoretical objective of forming such a fracture in the rock of the formation is to create a large surface area of the faces of the fracture. The large surface area allows oil and gas to flow from the rock of the subterranean formation into the fracture, which provides an easy path for the oil and gas to easily flow into the well.
However, once the high pressure is relieved by the escape of the fracturing fluid through the created fracture and out further into the subterranean formation, the fracture has a tendency to be squeezed closed by the natural pressures on the rock within the deep subterranean formation. To keep the fracture open, some kind of material must be placed in the fracture to prop the faces of the fracture apart.
The desirable material for the purpose of propping the fracture apart must meet several criteria. For example, the material must have a sufficient strength not to be entirely crushed by the natural forces tending to push the fracture closed. The material must be capable of being fluidized so that it can flow with or immediately following the fracturing fluid. Additionally, the material also must itself not block or seal the fracture. Thus, a typical material used for the purpose of propping open a fracture is sand. Sand, in the aggregate, has a sufficiently high mechanical strength to prop open a fracture in a subterranean formation at typical depths and natural subterranean pressures; it can behave as a fluid in that it can be poured and flow; and the particles, even when tightly compacted, have a network of void spaces between them that can provide high porosity and thus high permeability, thus allowing the produced fluids to flow through the propped fracture.
While sand is the most commonly used material for the purpose of propping the fracture open, many other materials of the appropriate size range and mechanical strength can be used. In the oil and gas industry, any suitable particulate material that is used for the purpose of propping open a fracture produced by hydraulic fracturing is called a “proppant.”
To be able to carry and place a proppant into a newly-created fracture, a fluid must have a sufficient viscosity to suspend and carry the proppant. In a low viscosity fluid, for example, the proppant would have a tendency to simply fall under gravity toward the bottom of the well instead of being carried with the fracturing fluid out into the newly-created fracture. For a fluid to be able to carry the proppant instead of having the proppant fall out of the fluid, the fracturing fluid needs to be made to have a much higher viscosity than that of water. Preferably, the fracturing fluid is a gel, which has a very high viscosity and great capacity for carrying a proppant suspended in the fluid.
Using a water-soluble polymeric material, such as a guar gum, is one of the ways to build viscosity in aqueous systems. Such a gum can be mixed with an aqueous fluid for use in a well to increase fluid viscosity. A sufficient concentration of the guar gum in an aqueous system can form a gel. Furthermore, the gum also can be crosslinked with other compounds to create a suitably viscous fluid, which is highly advantageous to transporting a proppant in a hydraulic fracturing procedure.
Another type of treatment for a subterranean formation is gravel packing, which is used to help control production of formation particles and to help control fines migrations. “Fines” are tiny particles, typically with a diameter of 43 microns or smaller, that have a tendency to flow through the formation with the production of hydrocarbon. The fines have a tendency to plug small pore spaces in the formation and block the flow of oil. As all the hydrocarbon is flowing from a relatively large region around the wellbore toward a relatively small area around the wellbore, the fines have a tendency to become densely packed and screen out or plug the area immediately around the wellbore. Moreover, the fines are highly abrasive and can be very harmful to pumping equipment.
In general, gravel packing involves placing sand or gravel around the wellbore to help filter out the formation particles and prevent them from flowing into the well with the produced fluids. Like with placing a proppant in a subterranean formation during hydraulic fracturing, a gelled fluid can be used to help place the gravel in a gravel packing operation. However, it is possible to use various fluids, both viscosified and non-viscosified, to help place the gravel pack, including water, brines, viscosified aqueous fluids, diesel, crude oil, viscosified diesel or crude, surfactant gels, etc.
After the proppant is mixed with the viscous fracturing fluid and pumped downhole to form a fracture, the fracturing fluid must be removed from the formation. It should be removed without moving the proppant from the fracture and without damaging the conductivity of the proppant bed. To accomplish this removal, the operator must thin the viscous fluid that transported the proppant to a very low viscosity near that of water for optimal removal from the propped fracture. Similarly, when a viscosified fluid is used for gravel packing, the viscosified fluid must be removed from the gravel pack. Reducing the viscosity of a viscosified fluid is referred to as “breaking” the fluid. Chemicals used to reduce the viscosity of fracturing fluids are called breakers.
Water-based fracturing fluids are usually made viscous by the addition of 20 to 70 pound (lb) of gelling polymer per 1,000 gallons (Mgal) of water (2.4-59 g/L). Typical gelling polymers include, for example, guar, guar derivatives, xanthan, chitosan, starch, starch derivatives, cellulose and cellulose derivatives.
For example, one of the most common gelling polymers used in the oil and gas industry is guar. Guar polymer, which is derived from the beans of a guar plant, is referred to chemically as a galactomannan gum. A mixture of guar dissolved in water forms a base gel, and suitable crosslinking agents are added to form a much more viscous fluid, called a crosslinked fluid. The water-based fluids discussed here may be crosslinked with metals ions, such as zirconium, titanium, or boron compounds. The viscosity of base gels are typically 20 to 50 cp; when it is crosslinked, the viscosity of the base gel is increased by 2 to 100 times depending on the temperature, test method, and type of crosslinker used.
Guar polymer is considered to have a molecular weight in the range of 2 to 4 million. Breakers reduce the molecular weight of guar polymer by cutting the long polymer chain. As the polymer chain is cut, the fluid's viscosity is reduced. For instance, reducing the guar polymer molecular weight to chains of about 10,000 molecular weight converts the fluid to near water-thin viscosity. A single guar polymer must be cut into approximately 200 small pieces to substantially eliminate its viscosity increasing effects.
On the other hand, crosslinking the guar increases its molecular weight to extremely high values. The crosslinking depends on the type of crosslinker, concentrations, temperature of the fluid, type of gelling polymer used, etc. Shear is required to properly mix the crosslinker and the gelling agent. Thus, the actual number of crosslinks that are possible and that actually form also depends on the shear level of the system: the total molecular weight is inversely proportional to the shear the fluid receives. The exact number of crosslink sites is not well known, but it could be as few as one to ten. The number of crosslinks, and thus the molecular weight of the resulting polymer, significantly alters fluid viscosity.
Crosslinks produced by borate ion are considered to be reversible and can be eliminated at neutral or acidic pH. Crosslinks formed by zirconium, titanium, antimony, and aluminum compounds, however, are considered to be not reversible and are broken by other methods than controlling pH. Fracturing fluid breakers are designed to reduce guar polymer viscosity by breaking down its molecular weight. This process can occur independently of crosslinking bonds existing between polymer chains. After the proppant is placed in the fracture and pumping stops, the fracture closes. The pores of the proppant bed and the surrounding formation are filled with the fracturing fluid and should be cleaned out. As noted above, the fracturing fluid must be removed to maximize conductivity of the proppant-filled fracture.
Removal of the fracturing fluid is facilitated by using breakers to reduce fluid viscosity. Unfortunately, another complicating factor also exists. As the hydraulic fracture is being formed and propagated in formations with permeability, fluid leaks from the fracture into the formation matrix. Because of the large size of the polymer, a filtration process occurs upon the fracture face. A filtercake of guar polymer is formed while the aqueous fluid, KCl, and breakers pass into the formation. Careful examination of this filtercake, which may be formed from crosslinked or uncrosslinked guar, reveals a semi-elastic, rubber-like membrane. Analysis shows the filtercake consists of approximately 95 percent water and 5 percent guar polymer. Even with this high water content, a filtercake can have these properties since the water is very tightly bound to the guar. The strength of hydrogen bonding between the polymer molecules makes the filtercake semi elastic and rubber like. Once the polymer concentrates it is difficult to solubilize the polymer. Non-filtercake fluid consists of approximately 99.5 percent water and 0.5 percent polymer. When the fracture closes, the permeability of the proppant bed may be damaged severely by the polymer filtercake. Viscosified gravel pack fluids need breakers, too. They may or may not form a filtercake on the formation face.
Breakers must be selected to meet the needs of each situation. First, it is important to understand the general performance criteria of breakers. In reducing the viscosity of the fracturing fluid to a near water-thin state, the breaker must maintain a critical balance. Premature reduction of viscosity during the pumping of a fracturing treatment can jeopardize the treatment. Inadequate reduction of fluid viscosity after pumping can also reduce production if the required conductivity is not obtained.
The ideal viscosity versus time profile would be if a fluid maintained 100% viscosity until the fracture closed on proppant and then immediately broke to a thin fluid. Some breaking inherently occurs during the 0.5 to 4.0 hours required to pump most fracturing treatments. One guideline for selecting an acceptable breaker design is that at least 50% of the fluid viscosity should be maintained at the end of the pumping time. This guideline may be adjusted according to job time, desired fracture length, and required fluid viscosity at reservoir temperature. A typical gravel pack break criteria is a 4-8 hour break time.
Several methods of characterizing the rheology of fracturing fluids are available. Rheological test results can be used to select a breaker or breaker package that gives the desired viscosity during and after pumping. The following criteria should also be considered when selecting a breaker: breaker influence on proppant transport; breaker influence on fracture conductivity; and economic considerations.
Chemical breakers used to reduce viscosity of natural gelling polymers used in fracturing or other subterranean applications such as guar and derivatized guar polymers are generally grouped into three classes: oxidizers, enzymes, and acids. All of these materials reduce the viscosity of the gel by breaking the polymer chain. The breakers operate by cleaving the backbone of polymer either by hydrolysis of acetal group, cleavage of glycosidic bonds, oxidative/reductive cleavage, free radical breakage or combination of these processes. A breaker should be selected based on its performance in the temperature, pH, time, and desired viscosity profile for each specific treatment.
Oxidizers commonly used to reduce viscosity of natural polymers includes, for example, sodium persulfate, potassium persulfate, ammonium persulfate, lithium and/or sodium hypochlorites, chlorites, peroxide sources (sodium perborate, sodium percarbonate, calcium percarbonate, urea-hydrogen peroxide, hydrogen peroxide, etc.), bromates, periodates, permanganates, etc. In these types of breakers, oxidation reduction chemical reactions occur as the polymer chain is broken.
Different oxidizers are selected based on their performance at different temperature and pH ranges. Consideration is also given to the rate of oxidation at a particular temperature and pH range. For example, the rate at which a persulfate molecule breaks into two radicals is temperature dependent. Below 120° F. (49° C.) this process occurs very slowly, and the reaction must be catalyzed to obtain acceptable break rates. A variety of catalysts, including various organic amines and inorganic materials, may be used for persulfate breakers. The optimum pH for persulfate oxidation is around 10 at low temperature (less than 150° F. or 66° C.). Above approximately 200° F. (93° C.), persulfate decomposes very quickly and breaks the polymer very quickly (i.e., with little delay in the break). Therefore, persulfate is not recommended as a breaker above 200° F. Similarly chlorites are used for high temperature breakage in the range of 150-350° F. with optimum pH range of 6-12. It can also be activated by catalysts such as cobalt acetate, EDTA, NTA, etc. Hypochlorites are generally used for low temperature breakage of natural polymers.
Enzymes are also used to break the natural polymers in oil field applications. They are generally used at low temperature (25 to 70° C. or 68° F. to 158° F.) as at higher temperature they denature and become ineffective. At very low temperatures enzymes are not as effective as rate of breakage of polymer is very slow and they are generally not recommended. Different types of enzymes are used to break different types of bond in the polysaccharides. Some enzymes break only α-glycosidic linkage and some break β-glycosidic linkage in polysaccharides. Some enzymes break polymers by hydrolysis and some by oxidative pathways. Generally Hemicellulase is used to break guar polymers and Xanthanase is used to break Xanthan polymers. A specific enzyme is needed to break a specific polymer/polysaccharide. Enzymes are referred to as Nature's catalysts because most biological processes involve an enzyme. Enzymes are large protein molecules, and proteins consist of a chain of building blocks called amino acids. The simplest enzymes may contain fewer than 150 amino acids while typical enzymes have 400 to 500 amino acids. Compared to persulfate with a molecular weight of 236, enzymes are large molecules with molecular weights in the range of 10,000. Compared to guar, which has an approximate molecular weight of 2-4 million, enzymes are small.
Acids also provide the same break via hydrolysis like enzymes. Acids, however, pose various difficulties for practical applications. Acids are not used as a polysaccharide polymer breaker very often because of cost, poor break rate control, chemical compatibility difficulties, and corrosion of metal goods.
In particular, there are few methods available to break viscosifying polymers, especially xanthan polymers, at very low temperatures (below 120° F./49° C.) and they suffer from various problems. For example, the use of hypochlorite poses corrosion concerns and may not provide sufficient delay of the break. The use of persulfate requires high concentrations at lower temperatures. The use of sodium chlorite is limited to high-temperature applications and may react violently to cause a fire when organic compounds are used in the process. Enzymes do not work well on xanthans.
Sodium perborate and ethyl acetoacetate (“EAA”) has been reported as being capable of breaking a gel of a typical xanthan gum polymer (“XANVIS”) down to 80° F. (27° C.). See Kelco Oilfield Group in its Technical Bulletin entitled “Breaker Applications,” revised January 2004. However, we were unable to break a xanthan gel at very low temperature using the published recipe and the publication does not provide sufficient detail to allow the user to optimize the breaker recipe for a given set of conditions.